Natural gas reserves often contain hydrogen sulfide (H.sub.2 S) as a major contaminant. Hydrogen sulfide is an acid gas that is toxic and corrosive in the presence of water. A significant portion of total gas production does not meet pipeline standards and needs treatment to reduce the H.sub.2 S concentration to 1/4 grain per 100 standard cubic feet (about 4 to 6 mg/L), or .ltoreq.4 ppm on a volume basis.
A commonly used commercial process for the removal of H.sub.2 S from the gas stream is the Amine process, followed by the Claus process for sulfur recovery. In the Amine process, the gas stream is contacted with the amine solvent to remove H.sub.2 S, then the amine solvent is heated to 194-302.degree. F. (90-150.degree. C.) to liberate H.sub.2 S and regenerate the solvent, which is recycled. Although the H.sub.2 S is removed from the sour natural gas stream, it still must be disposed of. Hydrogen sulfide generated during regeneration of the amine solvent can either be incinerated, which converts the hydrogen sulfide disposal problem into an air pollution problem due to the production of SO.sub.2, or treated by physicochemical methods such as the Claus process. In the Claus process, H.sub.2 S is fed into a reaction furnace, and the reaction gas is passed through a series of catalytic reactors to convert the H.sub.2 S into elemental sulfur. Although the Claus process produces a high quality elemental sulfur product, the process is often too expensive for small capacity plants, which are those having a capacity of less than 2 MMSCFD (million standard cubic feet per day) (about 56.6 million liters per day).
An alternative to the Amine/Claus process is liquid redox technology in which catalysts, including without limitation iron and vanadium catalysts, act as oxidizing agents in the mitigation of sulfides. Over the past three decades, liquid redox processes have been used in combination with sulfur mitigation and recovery processes for the treatment of a variety of sour gas streams. Many of these processes are described in "An Overview of Liquid Redox Sulfur Recovery", Chemical Engineering Progress, May 1989, pp 43-49, which is hereby incorporated by reference. In the sulfur mitigation and recovery processes, a sulfide mitigation catalyst is employed to oxidize sulfide compounds, thereby enabling removal of sulfide from the gas stream and eventual recovery of elemental sulfur. Liquid redox processes are better able to handle larger quantities of gases (up to 30 MMSCFD) (about 840 million liters per day).
However, the use of liquid redox processes has been limited and discouraged by high costs and the difficulty of regenerating sulfide mitigation catalysts which are used and reduced during such processes. These catalysts act as oxidizing agents upon sulfides such as H.sub.2 S and as a result are reduced themselves. For example, when ferric catalysts are used, the catalyst will typically be reduced during the liquid redox process from ferric to ferrous form as a result of the oxidation of sulfides. In order to be useful again, the sulfide mitigation catalyst must be regenerated by oxidation of its metal species.
Several liquid redox processes are available; among the most prominent are Stretford, Sulfolin, Sulferox.RTM., and the Wheelabrator Clean Air Systems-ARI-LO-CAT System.RTM.. The Stretford and Sulfolin processes use vanadium as the active metal for the redox reaction and as a result, vanadium is present in the recovered sulfur. Environmental restrictions make disposal of the vanadium tainted sulfur a major problem.
In several existing liquid redox systems, sour natural gas (natural gas mixed with one or more sulfide gases) contacts a ferric chelate compound in a mitigation reactor. In the mitigation reactor, the sulfide is oxidized by the ferric chelate and ultimately converted to elemental sulfur by the chemical process set forth in Equation 1: EQU H.sub.2 S+2Fe.sup.3+ .fwdarw.S+2H.sup.+ +2Fe.sup.2+ (Equation 1)
The ferric chelate compound, which has been reduced to ferrous form, is then removed to a regeneration chamber where it is regenerated.
One known method of regeneration is through aeration, or contacting the catalyst with air containing oxygen. Regeneration is accomplished by aeration in the chemical process set forth in Equation 2: EQU 1/2O.sub.2 +2Fe.sup.2+ +2H.sup.+ .fwdarw.2Fe.sup.3+ +H.sub.2 O(Equation 2)
The net reaction from mitigation and regeneration, combining Equations 1 and 2, is set forth below in Equation 3: EQU H.sub.2 S+1/2O.sub.2 .fwdarw.S+H.sub.2 O (Equation 3)
The spent catalyst is oxidized by the oxygen-containing air contacting the process solution which contains the catalyst. After regeneration, the catalyst is returned to the mitigation reactor for another turn in the mitigation of sulfide. These processes require a regeneration reactor which is separate from the mitigation reactor and thereby entail significant capital expense for a second reactor. Additional expenses associated with the regeneration reactor arise from the risk of explosion during the aeration procedure. Therefore, further additional capital expenditures and operating costs are required to minimize this risk of explosion.
Another possibility for regeneration is through the use of microorganisms which are capable of oxidizing the sulfide mitigation catalyst. In one process, which is the basis for a process known as Bio-SR, the ferrous sulfate formed during H.sub.2 S oxidation in accordance with Equation 4 is converted to ferric sulfate by the bacterium Thiobacillus ferrooxidans in accordance with Equation 5. EQU H.sub.2 S+Fe.sub.2 (SO.sub.4).sub.3 .fwdarw.FeSO.sub.4 +H.sub.2 SO.sub.4 +S(Equation 4) EQU 2FeSO.sub.4 +H.sub.2 SO.sub.4 +1/2O.sub.2 .fwdarw.Fe.sub.2 (SO.sub.4).sub.3 +H.sub.2 O (Equation 5)
In the Bio-SR method, regeneration occurs in a reactor separate from the one where sulfide is mitigated from sour natural gas.
Studies conducted at Texas A & M University show that reduced ARI LO-CAT II.RTM. catalyst (a ferric chelate sold by ARI as a sulfide mitigation catalyst) can be regenerated by biological treatment with Thiobacillus ferrooxidans in the presence of air. One advantage of this method is that the regeneration of the catalyst can occur in the same reactor as does the mitigation of sulfides by the catalyst. However, the utility of Thiobacillus ferrooxidans for regeneration at temperatures of 40.degree. C. (104.degree. F.) and higher is in question because of the maximum growth temperature for T. ferrooxidans. Highly thermophilic organisms are those which grow and thrive in temperatures above 40.degree. C.
In contrast, T. ferrooxidans grows in the temperature range of about 10.degree. C. to about 37.degree. C. (about 50.degree. F. to about 99.degree. F.). Little or no growth is seen at temperatures of 42.degree. C. (about 108.degree. F.) and above. Regeneration at higher temperatures is desirable because sour natural gas is generally introduced to reactors at higher temperatures, for example at 46.degree. C. (about 115.degree. F.), and mitigation of sulfide generally occurs at higher temperatures as well. Also, liquid redox plants often need to run sulfide mitigation reactors at temperatures up to 80.degree. C. (about 176.degree. F.) in order to evaporate water formed as a result of converting hydrogen sulfide to sulfur. One problem with the use of T. ferrooxidans to regenerate ARI LO-CAT II.RTM. catalyst is that an operator must frequently adjust the temperature of the reactor to a lower temperature to allow for the regeneration of the catalyst and the growth of the T. ferrooxidans microorganism.
Another disadvantage associated with the use of the T. ferrooxidans in the LO-CAT system is that T. ferrooxidans has generally been used as part of an aerobic regeneration process. Thus, many of the disadvantages previously mentioned in describing aerobic regeneration are applicable to the present use of T. ferrooxidans.
The LO-CAT process as generally practiced heretofore is shown schematically in FIG. 1. Sour natural gas or other gas to be desulfurized, such as landfill gas, geothermal gas, vent gas, biogas, or the like which contains sulfur species, passes from a sour natural gas source 20 through a coalescing filter 22 for removal of liquid droplets. The sour natural gas is then sparged into the reactor 24 through a sparger 26 and bubbled into the process solution 28 which may contain Thiobacillus ferrooxidans as a mitigation catalyst. The treated gas bubbles out of the process solution 28 and proceeds out of the reactor 24 through an exit conduit 30 to storage or a pipeline.
An air blower 32 supplies sufficient air to the reactor 24 to oxidize the reduced catalyst in a catalytic process and sour natural gas in an aeration process. Spent air, diminished in or without oxidizing capacity, is removed from the reactor 24 via the exit conduit 30.
Precipitated sulfur accumulates at the bottom cone 36 of the reactor 24. A filter feed pump 38 delivers sulfur slurry from the cone 36 to a belt filter 40. At the belt filter 40, wash water is sprayed on the filter cake to remove as much process liquid as possible, which is returned to the reactor 24. Sulfur filter cake is removed from the belt filter 40 to a reslurry vessel 42 where water is added to bring the percent of solids to about 20%. A slurry pump 44 may be employed to pump the sulfur slurry to the sulfur separator 46 where sulfur is separated from liquids. From the sulfur separator 46 the slurry passes to a sulfur filter 48 which separates smaller sulfur particles from liquids. Molten sulfur advances to the molten sulfur storage container 50 and the liquids recirculate to the reactor 24. A sulfur loading pump 52 may also be provided.